This invention relates to an improved method for the in-situ recovery of oil from oil-bearing formations containing viscous oils or bitumen. More particularly, the invention relates to an in-situ recovery method for the recovery of bitumen from tar sands by the injection of steam or a mixture of steam and an oxygen-containing gas wherein pressurization and drawdown cycles are employed and carbon dioxide is injected at the start of the pressurization cycle.
The in-situ recovery of low API gravity or viscous oils from subterranean oil-bearing formations and bitumen from tar sands has generally been difficult. Although some improvement has been realized in the in-situ recovery of heavy oils, i.e., oils having an API gravity in the range of 10.degree. to 25.degree. API, little success has been realized in recovering bitumen from tar sands by in-situ methods. Bitumen can be regarded as a highly viscous oil having an API gravity in the range of about 5.degree. to 10.degree. API and a viscosity in the range of several million centipoise at formation temperature, and contained in an essentially unconsolidated sand, generally referred to as a tar sand.
Extensive deposits of tar sands exist in the Athabasca region of Alberta, Canada. While these deposits are estimated to contain about seven hundred billion barrels of bitumen, recovery therefrom, as indicated above, using conventional in-situ techniques has not been altogether successful. The reasons for the varying degrees of success relate principally to the fact that the bitumen is extremely viscous at the temperature of the formation, with consequent very low mobility. In addition, the tar sand formations have very low permeability, despite the fact they are unconsolidated.
Since it is known that the viscosity of a viscous oil decreases markedly with an increase in temperature, thereby improving its mobility, thermal recovery techniques have been investigated for recovery of bitumen from tar sands. These thermal recovery methods generally include steam injection, hot water injection and in-situ combustion.
Typically, such thermal techniques employ an injection well and a production well traversing the oil-bearing or tar sand formation. In a conventional throughput steam operation, steam is introduced into the formation through an injection well. Upon entering the formation, the heat transferred to the formation by the hot aqueous fluid lowers the viscosity of the formation oil, thereby improving its mobility. In addition, the continued injection of the hot aqueous fluid provides the drive to displace the oil toward the production well from which it is produced.
Thermal techniques employing steam also utilize a single well technique, known as the "huff and puff" method, such as set forth in U.S. Pat. No. 3,259,186. In this method, steam is injected via a well in quantities sufficient to heat the subterranean hydrocarbon-bearing formation in the vicinity of the well. Following a period of soak, during which time the well is shut-in, the well is placed on production. After production has declined, the huff and puff technique may again be employed on the same well to again stimulate production. The application of single well schemes employing steam injection and as applied to heavy oils or bitumen is also taught in U.S. Pat. No. 2,881,838, which utilizes gravity drainage. In a later patent, U.S. Pat. No. 3,155,160 an improvement in U.S. Pat. No. 2,881,838 is described wherein steam is injected and appropriately timed pressuring and depressuring steps are employed. In the application to a field pattern, the huff and puff technique may be phased so that numerous walls are on an injection cycle while others are on a production cycle, which cycles are then reversed.
In the conventional in-situ combustion method, an oxygen-containing gas such as air is injected into the formation via an injection well and a combustion of a portion of the in-place oil adjacent the well is initiated. Injection of the air is continued, thereby establishing a combustion front that has a temperature generally in the range of 900.degree.-1200.degree. F. The continued injection of the air displaces the combustion front through the formation which front in turn displaces oil ahead of it through the formation to a production well from which the oil is produced. The combustion front is sustained by the combustion of a portion of the in-place oil during the movement of the front through the formation.
More recently, an improved thermal recovery method for low API crudes or bitumen has been disclosed in U.S. Pat. No. 4,006,778 which utilizes a controlled low-temperature oxidation (LTO). A mixture of steam and an oxygen-containing gas is injected into the formation to generate, and thereafter to control, an in-situ low-temperature oxidation. The mixture is injected at a temperature corresponding to the temperature of saturated steam at the pressure of the formation. By this method of low-temperature oxidation, the temperature level is established and is controlled in the formation at a temperature generally in the range of 250.degree. to 500.degree. F., which temperature is much lower than that of the conventional in-situ combustion process.
In other recent advancements, such as in the coassigned pending application Ser. No. 837,482, filed Sept. 28, 1977, now U.S. Pat. No. 4,127,172, the use of pressurization and drawdown cycles with the injection of thermal recovery fluids as a mixture of steam and an oxygen-containing gas has been described. Pressurization of the formation, for example, may be accomplished by employing a higher injection rate than the production rate. Thereafter, drawdown, which is a reduction in formation pressure, may be accomplished by producing at a rate greater than the injection rate.
Other methods for enhanced recovery described in the prior art include the use of an injection fluid such as a low molecular weight hydrocarbon or carbon dioxide that is soluble or miscible with the in-place crude. In the case of carbon dioxide, when it dissolves in oil, at pressures less than the miscibility pressure, viscosity reduction, and swelling of the oil occur in the formation which have beneficial results in increasing oil recovery. The use of carbon dioxide at pressures lower than the miscibility pressure for carbon dioxide and oil is described, for example, in U.S. Pat. No. 3,252,512; and the use of carbon dioxide at pressures of from about 1000 psi to about 4000 psi is taught in U.S. Pat. No. 2,623,596. Carbon dioxide may also be employed under conditions of conditional miscibility, as set forth in U.S. Pat. No. 3,811,502, which teaches a recovery method wherein the pressure of the formation is at, or adjusted to, the pressure at which the carbon dioxide is conditionally miscible with the oil in the formation.
Prior art also teaches the use of steam in combination with carbon dioxide. In U.S. Pat. No. 3,412,794 there is taught the recovery of oil by the injection of steam into the oil-bearing stratum with production restricted to a lower level, whereby heat loss is reduced by the injection of carbon dioxide into an upper-level, high permeability zone. In U.S. Pat. No. 3,452,492 there is taught a steam drive process whereby steam is injected for an extended period of time and thereafter a slug, solely of gas other than steam, for example, carbon dioxide, is injected so as to drive said steam and condensate deeper into the formation and to displace the oil therefrom. Thereafter, a second slug of steam is injected followed by another slug of gas.
In U.S. Pat. No. 3,908,762, there is disclosed the use of steam and a noncondensible gas such as carbon dioxide that is injected either simultaneously or separately and sequentially with the steam to establish a communication path in tar sand deposits for recovering viscous petroleum therefrom. In yet another teaching, U.S. Pat. No. 3,948,323, recovery of oil is effected by injecting a heated fluid comprising steam and a noncondensible gas such as carbon dioxide. After the injection rate diminishes to a predetermined level, a heated noncondensible gas without steam is injected until a desired injection rate is reached. The injection of the mixture of steam and noncondensible gas is then again undertaken.
We have now found that additional recovery of viscous oil or bitumen can be realized in an in-situ recovery process utilizing the injection of a thermal recovery fluid if carbon dioxide is injected with the injection of the thermal recovery fluid and the injection of the carbon dioxide is phased with pressurization and drawdown cycles employed during the operation.